The present invention relates generally to downhole measurements of fluid properties in a borehole, and more particularly to a tool for characterizing fluids at the bottom of the hole, including fluid flowing into the hole from the formation. Still more particularly, the present invention relates to a tool that uses acoustic measurements, including multi-frequency acoustic measurements, to obtain qualitative and quantitative measurements of the composition and phases of the liquid, its compressibility and its bubble point.
During the development and useful life of a hydrocarbon well it is often desirable to evaluate the fluids present in the surrounding formations to determine the quality of hydrocarbons present and the status of the well. Useful information about the formation fluid includes the composition and volume fraction of oil and water, the amount of solids contained in the fluid, compressibility of the fluid, and the pressure at which any entrained gases will bubble out of the fluid (bubble point). This information is helpful in determining the proper procedures to use for drilling and producing the well.
Historically, subterranean reservoir fluids were brought to the surface for analysis. There are many advantages to being able to analyze reservoir fluids while still in the well but downhole sampling and analysis of reservoir fluids presents a number of problems. One problem encountered in data acquisition downhole is the need to obtain a representative sample of reservoir fluid with minimum level of drilling fluid contamination. In the course of drilling, filtrate (drilling-mud based fluid) typically invades the formation in the vicinity of the wellbore. The process of conducting a formation test commonly involves acquiring a sample of reservoir fluid by running a conduit into the wellbore and providing a pressure drop so that fluid will flow into the conduit. The first fluid to reach the tool will comprise mainly the drilling fluid filtrate coming back out of the formation. Over time reservoir fluids displace this filtrate. Since the objective is to sample and analyze the reservoir fluids, rather than the filtrate, it is necessary to wait until the reservoir fluid has substantially displaced the filtrate from the sampling device. Thus, it is desirable to monitor the drilling fluid level in the fluid stream and to determine when an acceptable maximum level of contamination is reached so that a representative fluid sample can be obtained. A maximum level of one hundred parts per million of contaminant is acceptable for all known applications. Even samples with 70% contaminant can sometimes be useful with accurate knowledge of contaminant fraction.
Accordingly, there has been a continuing need to develop a fluid analysis system capable of accurately assessing the quality of the wellbore fluid and measuring the composition of the reservoir fluid. In particular, there has been a need to provide a method and system for measuring level of drilling fluid contamination in fluid sample, and for performing in-situ quantitative fluid analysis to determine gas bubble point, water-oil ratio, fluid composition, and compressibility of the reservoir fluid. Some prior art has disclosed methods of measuring fluid properties downhole but these methods are limited in the amount of information available.
U.S. Pat. No. 3,914,984, issued to Wade, discloses a method of measuring solid and liquid droplets in a liquid using ultrasonic tone-burst transmission in a sample cell. U.S. Pat. No. 4,381,674, issued to Abts, describes a method of detecting and identifying scattering media in an oil recovery system by counting the number of ultrasonic pulses reflected from the scattering media and comparison with the ultrasonic energy attenuation. U.S. Pat. No. 4,527,420, issued to Foote, describes a method and apparatus of using scattered ultrasound to identify solid particles and liquid droplets, specifically for semiconductor and chemical process monitoring applications. International Application Publication No. WO 98/34105, invented by Nyhavn, describes a method and apparatus for inspecting a fluid flow in a hydrocarbon production well using a method of qualitatively analyzing scattering media using acoustic signals scattered or reflected in the fluid flow. U.S. Pat. No. 4,571,693, issued to Birchak et al., describes a device for downhole measurement of multiple parameters such as attenuation, speed of sound, and density of fluids. The device consists of a gap to be filled with the fluids and a void to provide reference echo for attenuation measurement calibration but does not utilize a conduit to enable the flow of fluids through the tool. Other prior art devices have employed optical sensors and utilized a visible and near-infrared absorption spectrometer to identify the type of formation fluid, i.e. to differentiate between oil, drilling mud, water and gas present in the formation fluid. However, the windows of the optical devices may become coated with hydrocarbons (asphaltene, paraffin) that may distort their results. The devices also suffer from small depth of penetration for opaque fluids, which reduces their accuracy.
Despite the teachings of the foregoing references, it is still desired to provide a method for determining drilling fluid contamination and characterizing fluid media in situ. It is further desired to provide a downhole device that can detect and analyze gas bubbles and fine sand particles. Such a device would greatly improve reservoir fluid sampling and testing.
The present invention relates generally to fluid characterization in downhole reservoir fluid sampling and description applications. More specifically, this disclosure provides a method and apparatus for using acoustic transducers to detect and identify gas bubbles, solid particles, and/or liquid droplets in fluids. In one embodiment, the method comprises transmitting an acoustic signal through the fluid and using the received acoustic signal to determine the speed of sound in the fluid and the attenuation of the signal in the fluid. These measurements, along with a measurement of the density of the fluid can be used to calculate the compressibility of the fluid, fluid composition, solids content, and bubble-point of the fluid.
The present invention measures the fluid speed of sound and acoustic attenuation as a function of frequency and/or pressure. From the speed of sound, the fluid type and presence of mixtures can be determined. From speed of sound data combined with density, the compressibility of the fluid can be determined. Attenuation as a function of pressure is used to determine the bubble point pressure. In turn, these values can be used qualitatively and/or quantitatively to obtain information about the presence and size of solids in the fluid stream, contamination by solids or immiscible liquids, compressibility and the bubble point of the fluid stream.
Capabilities of the present method and apparatus may include, but are not limited to:
providing a qualitative indication of the extent of drilling fluid contamination in formation fluid;
providing a qualitative distinction between gas and liquid, water and oil, and crude oil and drilling mud fluid;
detecting gas vapor and gas bubbles in formation fluids;
providing a way to determine compressibility of the fluid;
providing a quantitative indication of oil/water ratio; and
providing a quantitative indication of solid particle size and concentration.